Fortnightly - H. Robert Erwinhttp://www.fortnightly.com/tags/h-robert-erwin
enCongestion on Trialhttp://www.fortnightly.com/fortnightly/2013/05/congestion-trial
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>PJM and the crisis over FTR underfunding.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-bio field-type-text-long field-label-inline clearfix"><div class="field-label">Author Bio:&nbsp;</div><div class="field-items"><div class="field-item even"><p><b>Bruce W. Radford</b> is publisher of <i>Public Utilities Fortnightly</i>. Contact him at <a href="mailto:radford@pur.com">radford@pur.com</a>.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - May 2013</div></div></div><div class="field field-name-field-import-image field-type-image field-label-above"><div class="field-label">Image:&nbsp;</div><div class="field-items"><div class="field-item even"><img src="http://www.fortnightly.com/sites/default/files/1305-CW-fig1.jpg" width="1350" height="943" alt="Figure 1 - A Growing Funding Shortfall" title="Figure 1 - A Growing Funding Shortfall" /></div><div class="field-item odd"><img src="http://www.fortnightly.com/sites/default/files/1305-CW-fig2.jpg" width="938" height="445" alt="Figure 2 - A Simple Grid" title="Figure 2 - A Simple Grid" /></div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p>PJM’s latest crisis—the underfunding of financial transmission rights that we’ve seen over the last few years—pushes regulators right to the edge. How far do they trust wholesale power markets? Do they accept the idea, proven by a famous economist, that freely traded financial instruments can work just as well—better even—than firm, physical contract rights?</p>
<p>In PJM’s case, we are told, the problem occurs when too much negative congestion shows up in real-time balancing. But if congestion is bad, shouldn’t negative congestion be good?</p>
<p>Some lay blame on what they say was likely an oversight—an error that PJM made back in June 2000 when it reconfigured its energy market to adopt a twin settlement system, by adding a day-ahead market as a second market clearing interval, in addition to real-time balancing, but somehow forgot at the same time to correct its FTR funding formula to mesh with the new regime.</p>
<p>Whatever the story, the problem seems first to have emerged in earnest about three years ago, according to testimony given by Brian Farley, director of wholesale transactions for FirstEnergy Solutions, which recently filed a complaint seeking redress at the Federal Energy Regulatory Commission. </p>
<p>It was March 2010, as Farley recounts, when FTR payout ratios in PJM first began to turn south, in a trend that has only grown worse with each passing year. For the 2010 and ’11 planning period—running June 1 through May 31—the FTR payout ratio was only 85 percent, producing a revenue inadequacy for PJM market participants of some $254 million. For 2011-’12, the ratio was even worse, at 81 percent. And for the first seven months of the current planning period, 2012-’13, the payout ratio had fallen to an anemic 76 percent.</p>
<p>All told, the FirstEnergy complainants say they have lost nearly $55 million in revenue owned to them as a holder of FTRs acquired to hedge congestion costs: $45.9 million from the funding shortfall, and $9.1 million via an FTR uplift charge—none of which, they say, stems from costs “caused” by their actions, or “from any speculative energy trading activity.”</p>
<p>They ask FERC to rule that PJM’s formula for funding FTRs is no longer just and reasonable. <i>(See, Complaint of FirstEnergy Cos., FERC Dkt. EL13-47, filed Feb. 14, 2013.)</i></p>
<p>Alert to the trend, PJM’s Market Implementation Committee had voted in March 2011 to create a task force to investigate the problem and recommend a fix. Since then, as Farley notes, the FTR task force (FTR-TF) has met numerous times, proposing all manner of solutions, as reported in a 50-page white paper released a year ago. <i>(See, “</i><a href="http://www.pjm.com/~/media/documents/reports/20120430-ftr-revenue-stakeholder-report.ashx" target="_blank"><i>FTR Revenue Stakeholder Report</i></a><i>,” Apr. 30, 2012, available on the PJM web site.) </i></p>
<p>By all accounts, PJM stakeholders have been debating the FTR underfunding issue now for about 30 months, but to no avail. PJM itself has acknowledged the stalemate:</p>
<p>“Suffice it to note,” as PJM wrote in its answer to FirstEnergy, filed March 17 of this year, “that the membership, as a collective, is hopelessly divided and unable to move forward with any reform in an area where a majority regards even the status quo as undesirable.”</p>
<h4>Symptoms and Causes</h4>
<p><span class="s3">On the surface, FTR underfunding stems from a mismatch in the PJM tariffs.</span></p>
<p>This mismatch occurs between how PJM defines the payout obligations owed to FTR holders, versus the way PJM defines the sources of revenues to be collected to pay off those FTR obligations. The obligations are fixed solely in terms of day-ahead congestion, that being the nodal differentials in day-ahead locational marginal energy prices, or LMP. By contrast, the source of funding those FTR obligations comes from both day-ahead and real-time balancing congestion—of which the latter increasingly turns out to be negative. Of all the regional grids with organized power markets, only ISO-NE does it this way. And New England reportedly copied this element of its tariff directly from PJM.</p>
<p>When FERC first approved PJM’s move to an LMP-based energy market, with FTRs to create a new type of financially firm transmission service to replace physical rights and allow traders to “buy through” the congestion, that approval was founded in part on Harvard Prof. Bill Hogan’s novel theorem.</p>
<p>And that theory states that any given array of FTRs plotted over a particular set of transmission paths, and then allocated or sold to regional market participants, will be revenue-adequate if 1) the grid operator can confirm beforehand that the FTRs as a group are simultaneously feasible, and 2) if the grid topology or configuration is the same for both a) the original issuance of FTRs, and b) the security-constrained, bid-based economic dispatch that clears the market and sets the LMPs, which in turn define the payoff for those FTRs.</p>
<p>In such a case, as Hogan explained in a paper he submitted to the FERC record in the FirstEnergy FTR underfunding complaint, “then no matter what the pattern of actual loads and generation, [an] economic dispatch with locational prices would be revenue-adequate.” <i>(See, Hogan, “Financial Trans. Rights, Revenue Adequacy and Multi-Settlement Electricity Markets,” p. 2, in Attachment A with comments of the Financial Institutions Energy Group, FERC Dkt. EL13-47, filed Mar. 18, 2013.)</i></p>
<p>Others, however, such New Jersey Attorney General Jeffrey Chiesa, who opposes the FirstEnergy complaint on behalf of his state Board of Public Utilities, remain unimpressed with such theories.</p>
<p>As Chiesa argues, the increased negative real-time balancing congestion that has put FTR funding underwater is only a symptom. The real source of FTR underfunding, he posits, are the more profound causes identified in PJM’s April 2012 stakeholder report on FTR underfunding.</p>
<p>That report noted a handful of true causes, most of which concern a “less-tight” seam around the PJM footprint, creating problematic transactions on borders and interfaces with the Midwest ISO and other external balancing areas—all of which make it difficult for PJM to accurately predict day-ahead market conditions, which in turn exposes PJM to eventual balancing corrections that increasingly create negative congestion (<i>i.e.,</i> real-time congestion that fails to generate revenue for PJM to use in paying off FTRs).</p>
<p>Among these identified causes:</p>
<ul>
<li>Many more market-to-market flowgates, especially with MISO;</li>
<li>Intermittent resources (read “wind”) suddenly showing up at the PJM border in real time (wind generally doesn’t offer day-ahead); and</li>
<li>An increasing lack of coordination of transmission outage planning across seams.</li>
</ul>
<p>And the shale-gas revolution and shutdown of aging coal plants might be playing a role as well. For example, PJM reports “reduced internal PJM west-to-east flows due to a relative increase in coal resource offer prices in the western part of the PJM region and a relative reduction in gas-fired resource offer prices in the eastern part.”</p>
<p>The April 2012 report also notes that 188 new market-to-market flowgates were added to the PJM-MISO coordination process during the prior two years, 150 of them at MISO’s request. Consultant Roy Shanker testified on this last point in his affidavit filed on behalf of DC Energy and Vitol:</p>
<p>“There is nothing wrong per se with creating new flow gates… If PJM knew about these new flowgate constraints … the constraint would be part of the model and less rights would be feasible and less rights awarded. The problem occurs because the Joint Operating Agreement [with MISO] allows for these elections of new flowgates in between annual FTR auctions. When this occurs, rights that previously had been feasible may become infeasible, and underfunding will occur.” <i>(Prepared direct testimony of Roy Shanker, p. 21, filed Mar. 18, 2013.)</i></p>
<p>To provide perspective, Exelon explains why all these factors, taken together, can lead to underfunded FTRs:</p>
<p>“The common thread among these causal factors is that PJM cannot accurately predict and reflect such occurrences in its day-ahead market model. When such conditions occur, the day-ahead market and the real-time market topology deviate, often resulting in transmission constraints that increase real-time congestion costs.” </p>
<p>And DC Energy General Counsel Joelle K. Ogg and Vitol Legal Compliance Director Robert Viola offer a telling observation:</p>
<p>“As PJM grew geographically—both via geographic expansion and joint coordination along an increasingly large set of seams—so too did the magnitude of negative balancing congestion.” <i>(See, Comments of DC Energy LLC and Vitol, Inc., p. 9, FERC Dkt. EL13-47, filed Mar. 18, 2013.)</i></p>
<p>Overall, PJM was quite candid in its answer filed at FERC, agreeing with much of what was documented in the FirstEnergy complaint:</p>
<p>“While negative balancing congestion is common because transmission system capability in the real-time energy market is generally the same or lower than … day-ahead … the growing trend of increasing negative balancing congestion is alarming.”</p>
<h4>Searching for Solutions</h4>
<p>In their complaint, the FirstEnergy companies propose to exclude real-time balancing congestion from the FTR funding calculus, so that FTR revenue adequacy is dependent only on congestion in the day-ahead market—a solution that even PJM says it would support.</p>
<p>And this proposed change, as noted by Edison Mission Marketing &amp; Trading, in its comments filed at FERC, would make PJM’s FTR calculations consistent with those of MISO and the New York and California ISO.</p>
<p>Robert Stoddard, a vice president at Charles River Associates (CRA), provides a bit more detail in his affidavit:</p>
<p>“Of the four other such RTOs with a two-settlement system, only ISO New England also pools the day-ahead and balancing market congestion credits to fund FTRs and allows the potential for systematic underfunding …</p>
<p>“The other three RTOs [CAISO, MISO, and NYISO] either fund FTR solely from day-ahead congestion receipts, and/or guarantee full payment.”</p>
<p>The difficult question, however, is what to do with the cost of the negative real-time balancing congestion, if it’s no longer netted against positive day-ahead congestion receipts. That’s where the real argument lies.</p>
<p>FirstEnergy proposes that FERC should order PJM to allocate the leftover real-time balancing congestion costs <i>pro rata</i> to all transmission users, as a class, since it’s impossible to identify any particular market participant or group of participants as responsible for causing these expenses. </p>
<p>State regulators from Maryland, New Jersey, Indiana, Ohio, and Pennsylvania oppose that idea, complaining that it would force balancing congestion costs largely on retail ratepayers, while letting many FTR holders go free—to the extent that they might use their financial hedging rights only to back up virtual trades, to avoid falling within any defined class of grid “users.”</p>
<p>Listen to Maryland PSC general counsel H. Robert Erwin, Jr., commenting on behalf of his state commission:</p>
<p>“The Maryland PSC strongly opposes this request, which could impose a $25 million or greater annual cost increase upon Maryland electricity end users and a $250 million or greater cost increase upon PJM-wide transmission end users.” <i>(Comments, p. 3, FERC Dkt. EL13-47, filed Mar. 18, 2013.)</i></p>
<p>A protest filed by the PJM Industrial Customer Coalition, plus three rural co-ops from North Carolina, Maryland, and Virginia, puts it a little more bluntly:</p>
<p>“FirstEnergy’s proposed solution is reactionary and heavy handed.”</p>
<p>In fact, many of the commenting state regulators seem to hold the opinion that FTRs are designed only for rank speculation, so that the holders ought to be prepared to bear the risk that funding for FTR payouts might fall short.</p>
<p>Maryland’s Erwin is one who gives voice to this notion, arguing that if FERC should approve FirstEnergy’s proposal to force significant uplift charges on end users to cover negative balancing congestion no longer allocated to FTR holders, then “it is necessary that this commission [FERC] require a demonstration from PJM and/or transmission owners that these additional FTRs are indeed stimulating valuable, beneficial market activity.”</p>
<p>Commenting on behalf of the New Jersey Board, Chiesa adds:</p>
<p>“FTRs are no longer representative of the costs associated with [the] LSEs’ historic investment in transmission, but rather a speculative financial hedge …</p>
<p>“Like any speculative investment, there is also no guarantee that FTR transactions will result in profit.”</p>
<p>Monitoring Analytics, the PJM Independent Market Monitor, led by its President and General Counsel Joseph Bowring and Jeffrey Mayes, picks up on this thread.</p>
<p>The IMM points out that PJM changed policy in 2003, ending the practice of allocating FTRs directly to load-serving utilities, and instead began its current plan of furnishing utilities only with ARRs—auction revenue rights, which entitle the holder to receive the revenue stream from auction sales of the actual FTRs. This change, the IMM argues, means that if there’s to be any sort of regulatory compact to ensure that congestion rights are adequately funded, it should extend only to ARRs, which serve as a <i>quid pro quo</i> substitute for the physical grid rights that utilities willingly gave up for PJM’s market vision. Such protection shouldn’t extend to FTRs, according to the market monitor, as they no longer serve the public interest, but only aid in financial speculation:</p>
<p>“ARRs [now] are directly allocated to loads in recognition of the fact that loads pay for the transmission system,” the monitor writes.</p>
<p>“PJM created the split between ARRs and FTRs … to provide the appropriate protection against congestion for load [via ARRs] … and to permit … those market participants who wished to use FTRs to speculate.”</p>
<p>This notion, that ARRs are somehow good, and FTRs bad, strikes CRA’s Stoddard as nonsensical:</p>
<p>“I strongly disagree with the Market Monitor’s unsupported assertion…</p>
<p>“The value of ARRs is dependent on the value of FTRs. In the extreme case, if market participants expected FTRs to be completely unfunded, they would be unwilling to pay anything for FTRs and, in turn, ARR holders would receive no auction revenues.”</p>
<p>PJM counsel Jeanine Watson seems to agree:</p>
<p>“Reduced prices for FTRs leads to less money to fund ARRs.</p>
<p>“ARRs are held by the load-serving entities, so, in the end, it is the load-serving entities that will be ultimately impacted by the reduced FTR revenues—one way or another.”</p>
<h4>Going Granular</h4>
<p>While PJM confirms that it “generally supports” the FirstEnergy proposal to remove the often-negative real-time congestion from FTR funding, and to reallocate that congestion, “whether negative or positive,” to all grid customers, it believes that this reallocation “would be improved” by defining “grid customers” as broadly as possible.</p>
<p>And that might help bring the doubting state PUCs on board.</p>
<p>In this case, PJM recommends that FERC should take the FirstEnergy complaint proposal and expand it so that the real-time congestion charges—the costs and revenues—are allocated not only to all physical grid injections and withdrawals of actual megawatt-hours, but also to virtual supply and demand deviations, plus an obscure category of transactions known in the trade as “up-to congestion,” which operate as pseudo-FTRs that can hedge congestion in the real-time market.</p>
<p>Presumably, PUCs and load-serving utilities would welcome this offer to hit virtual traders, often seen as financial speculators, just as hard or harder than retail ratepayers. Yet, as might be expected, this counterproposal has prompted a backlash from the financial community.</p>
<p>An ad-hoc group of financial marketers—Cobalt Capital Partners, Twin Cities Power Holdings, Red Wolf Energy Trading, and XO Energy—claim that virtual trading produces real value by fostering price convergence between day-ahead and real-time energy markets. They also cite analysis from Prof. Hogan that trying to push such costs onto purely financial transactions will backfire, since virtual traders will just take their money and go somewhere else:</p>
<p>“By contrast,” Hogan writes, “real load, in real time, has nowhere to go. Financial participants have many more options.”</p>
<p>Independent consultant Roy Shanker offers another way forward. He recommends breaking up PJM’s model of yearly FTR planning into smaller, more granular bites.</p>
<p>At present, PJM conducts its simultaneous feasibility test for allocating ARRs and auctioning off FTRs only once each year, for each separate planning period, making assumptions about grid outages, facility ratings, loop flows, interface ratings, and the like, before estimating the maximum allowable quantity of ARRs and FTRs. As PJM explains, this SFT process “spans approximately five months,” starting in mid-January and ending on May 31, the day before the start of the next planning year. <i>(Answer of PJM, p. 16, FERC Dkt. EL13-47, filed March 17, 2013.)</i></p>
<p>Yet, as Shanker points out, while grid capacity and configuration are constantly changing, the FTRs approved for auction through this annual SFT process are expected to remain viable across the entire planning year. Thus, Shanker suggests conducting the SFT analysis and ARR-FTR process much more frequently, such as seasonally or even monthly: “This would allow for much more granular resolution of changes in system topology.” <i>(See, Shanker, Direct Testimony, p. 7, FERC Dkt. EL13-47, filed March 18, 2013.)</i></p>
<p>As Shanker explains, PJM currently will exclude a transmission element from its assumptions about grid facility capacity if a planned outage on that line is to last longer than two months:</p>
<p>“So a number of seven-week outages could exist,” he notes, “and the annual model would allow rights to be awarded as if the lines were in service all 52 weeks of the year.</p>
<p>“The annual process,” Shanker adds, “has no seasonal representations, and thus ‘misses’ material outages, resulting in the award of rights for transmission that does not exist.”</p>
</div></div></div><div class="field-collection-container clearfix"><div class="field field-name-field-sidebar field-type-field-collection field-label-above"><div class="field-label">Sidebar:&nbsp;</div><div class="field-items"><div class="field-item even"><div class="field-collection-view clearfix view-mode-full field-collection-view-final"><div class="entity entity-field-collection-item field-collection-item-field-sidebar clearfix">
<div class="content">
<div class="field field-name-field-sidebar-title field-type-text field-label-above"><div class="field-label">Sidebar Title:&nbsp;</div><div class="field-items"><div class="field-item even">Understanding Negative Congestion: How FTRs become underfunded in real time</div></div></div><div class="field field-name-field-sidebar-body field-type-text-long field-label-above"><div class="field-label">Sidebar Body:&nbsp;</div><div class="field-items"><div class="field-item even"><!--smart_paging_autop_filter--><!--smart_paging_filter-->Negative congestion can arise during the real-time or balancing settlement, in a twin-settlement market like PJM—with separate day-ahead, and real-time market-clearing intervals. Robert Stoddard, a vice president at Charles River Associates, explains this phenomenon in his filings in support of the recent complaint filed by FirstEnergy, asking the Federal Energy Regulatory Commission (FERC) to resolve the problem of FTR underfunding in PJM. (See, FERC Dkt. EL13-47, filed Feb. 15, 2013.)
Figure 2 is taken from the three Stoddard Exhibits, RBS-2 through RBS-4.
Assumptions: Assume a simple electric grid with two nodes, A and B, with generating plants located at each node (Gen A at node A, Gens B1 and B2 at node B), a utility load of 500 MW at node B (LSE B), and a maximum grid transfer capability from A to B of 500 MW. The respective maximum outputs and marginal running costs for the three generating plants are given in the diagram.
Base Case: Day-Ahead Clearing Only: In the DA least-cost dispatch, Utility B’s 500-MW load is served 300 MW by Gen A, 180 MW by Gen B1, and 20 MW by Gen B2. The LMPs at the two nodes are $30 (A) and $42 (B). Total DA congestion = $3,600 (the difference between what load pays at Node B ($21,000 = 500 MW x $42), and the sum of what the Gens receive in total energy sales revenues ($17,400) at both A ($9,000 = 300 MW x $30) and B ($7,560 = 180 MW x $42). This figure ($3,600) is also the total funding available to be paid to FTR holders. FTRs are 100-percent funded.
Case 1: Load = 450 MW(DA); 500 MW(RT): This case creates an FTR funding surplus of $360, even though there’s no DA congestion, as the LMPs at A and B are both $30, because the smaller 450-MW DA load can be served entirely by the two lowest cost plants, Gen A and Gen B1. The $360 surplus stems entirely from RT balancing congestion. DA Load pays $13,500 (450 MW x $30), the same as $13,500 in total DA revenues paid to Gen A ($8,100 = 270 MW x $30) plus B1 ($5,400 = 180 MW x $30). But in the RT re-dispatch, in order to serve the extra 50 MW of load, output must increase at Gens A (30 MW) and B1 (20 MW), at a total cost of $1,740: $900 for Gen A (30 MW x $30) and $840 for Gen B1 (20 MW x $42). Load must pay an extra $2,100 for this RT re-dispatch (40 MW x $42). The difference of $360 ($2,100 minus $1,740) is the FTR funding surplus.
Case 2: RT Forced Transmission Outage: In this case, DA conditions are the same as in the base case, producing $3,600 in congestion and FTR obligations, but the transmission link between Nodes A &amp; B goes down completely in real time. This outage will create negative RT balancing congestion of $3,600. That’s because in the RT re-dispatch, load must now pay an extra congestion charge of $3,600, but the PJM RTO can’t collect those revenues; they go instead to Gens B1 and B2, as part of the higher LMP energy sales price at Node B, due to the transmission outage. Load will now pay an additional $3,600. Load avoids the $9,000 payment to buy 300 MW from Gen A at a price of $30, but now incurs an extra payment of $12,600 to replace that 300 MW by buying from Gen B2 at $42. At the same time, Gens B1 (180 MW) and B2 (320 MW) sell more power collectively, but because they sell at Node B, with a higher LMP of $42, they pocket the entire $21,000. Gen B1 gets $7,560 (180 MW x $42), and B2 gets $13,440 (320 MW x $42). The RT redispatch adds $3,600 in congestion, but it’s negative congestion, as PJM earns no compensation with which to fund payments to FTR holders.—BWR</div></div></div> </div>
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<div class="field-label">Tags:&nbsp;</div>
<div class="field-items">
<a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/ftr">FTR</a><span class="pur_comma">, </span><a href="/tags/financial-transmission-rights">financial transmission rights</a><span class="pur_comma">, </span><a href="/tags/day-ahead">day-ahead</a><span class="pur_comma">, </span><a href="/tags/brian-farley">Brian Farley</a><span class="pur_comma">, </span><a href="/tags/firstenergy-solutions">FirstEnergy Solutions</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ftr-tf">FTR-TF</a><span class="pur_comma">, </span><a href="/tags/locational-marginal-price">Locational marginal price</a><span class="pur_comma">, </span><a href="/tags/lmp">LMP</a><span class="pur_comma">, </span><a href="/tags/iso-ne">ISO-NE</a><span class="pur_comma">, </span><a href="/tags/bill-hogan">Bill Hogan</a><span class="pur_comma">, </span><a href="/tags/jeffrey-chiesa">Jeffrey Chiesa</a><span class="pur_comma">, </span><a href="/tags/midwest-iso">Midwest ISO</a><span class="pur_comma">, </span><a href="/tags/miso">MISO</a><span class="pur_comma">, </span><a href="/tags/wind">Wind</a><span class="pur_comma">, </span><a href="/tags/shale-gas">Shale gas</a><span class="pur_comma">, </span><a href="/tags/coal">coal</a><span class="pur_comma">, </span><a href="/tags/roy-shanker">Roy Shanker</a><span class="pur_comma">, </span><a href="/tags/exelon">Exelon</a><span class="pur_comma">, </span><a href="/tags/dc-energy">DC Energy</a><span class="pur_comma">, </span><a href="/tags/joelle-k-ogg">Joelle K. Ogg</a><span class="pur_comma">, </span><a href="/tags/vitol">Vitol</a><span class="pur_comma">, </span><a href="/tags/robert-viola">Robert Viola</a><span class="pur_comma">, </span><a href="/tags/edison-mission-energy">Edison Mission Energy</a><span class="pur_comma">, </span><a href="/tags/robert-stoddard">Robert Stoddard</a><span class="pur_comma">, </span><a href="/tags/charles-river-associates">Charles River Associates</a><span class="pur_comma">, </span><a href="/tags/cra">CRA</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/caiso">CAISO</a><span class="pur_comma">, </span><a href="/tags/nyiso">NYISO</a><span class="pur_comma">, </span><a href="/tags/h-robert-erwin">H. Robert Erwin</a><span class="pur_comma">, </span><a href="/tags/monitoring-analytics">Monitoring Analytics</a><span class="pur_comma">, </span><a href="/tags/joseph-bowring">Joseph Bowring</a><span class="pur_comma">, </span><a href="/tags/jeffrey-mayes">Jeffrey Mayes</a><span class="pur_comma">, </span><a href="/tags/auction-revenue-rights">auction revenue rights</a><span class="pur_comma">, </span><a href="/tags/arr">ARR</a><span class="pur_comma">, </span><a href="/tags/jeanine-watson">Jeanine Watson</a><span class="pur_comma">, </span><a href="/tags/cobalt-capital">Cobalt Capital</a><span class="pur_comma">, </span><a href="/tags/twin-cities">Twin Cities</a><span class="pur_comma">, </span><a href="/tags/red-wolf">Red Wolf</a><span class="pur_comma">, </span><a href="/tags/xo-energy">XO Energy</a> </div>
</div>
Fri, 03 May 2013 04:17:29 +0000meacott16568 at http://www.fortnightly.com